As the pandemic sends shock waves through the energy industry, investors are rethinking their bets on America’s decade-long natural gas boom.
On June 28th, Chesapeake Energy filed for Chapter 11 bankruptcy.
It was a long-expected announcement. The hydraulic fracturing pioneer – launched by a young Oklahoma wildcatter named Aubrey McClendon and a friend with a $50,000 investment in 1989, and at its peak in 2008 the second biggest producer of natural gas in the U.S. – had limped along under the weight of billions in debt for years. The unprecedented plunge in demand for oil and natural gas wrought by the Covid-19 pandemic just gave Chesapeake the finishing blow.
A turbulent and hugely consequential chapter in the history of American energy ended with it. As an energy analyst at the consultancy Woods Mackenzie observed the day after Chesapeake’s announcement, “The ‘growth at all costs’ model is now out the window.”
Over the past 15 years, Chesapeake and its many competitors in shale formations like Appalachia’s Marcellus and Texas’ Eagle Ford and Permian Basins used hydraulic fracturing technology to unleash a flood of cheap fossil gas. When prices dropped, these companies simply borrowed more money, signed more leases, and drilled for more gas. The ensuing glut dropped prices even lower, crushing the balance sheets of many producers.
“You look at their finances, they’ve been a basket case for a decade,” said Clark Williams-Derry, an analyst with the Institute for Energy Economics and Financial Analysis (IEEFA). “Their business model is ‘Let’s produce as much as humanly possible and just hope the price goes up.’”
Eventually, Wall Street grew tired of Chesapeake’s inability to turn a profit and pay back dividends to shareholders. The company’s market capitalization fell from a peak of $37 billion in June 2008 to $120 million in June 2020.
A few days earlier, on June 25th, Sable Permian Resources – a Texas oil and gas producer formed from a merger with the company that McClendon launched in 2014, just after he was pushed out of Chesapeake by investors concerned about his free-spending ways – filed for Chapter 11 bankruptcy, too.
“The investment community is now telling companies like Chesapeake, ‘We don’t want you anymore.’ And even the best companies in the oil and gas sector [are being told] ‘Stop spending so much money,’” said one former energy fund manager at a major asset management firm.
All throughout Chesapeake’s rise and fall, McClendon had played the role of the Pied Piper of U.S. natural gas. “I am not ashamed whatsoever to be the No. 1 pitchman for my product,” he said in an interview in 2008, the same year that Fortune magazine dubbed him “Mr. Gas.” “I believe in it with my heart and soul.”
With the demise – in the space of one week – of the two major companies McClendon founded, and the shale gas industry’s finances in tatters and investors fleeing, amidst a global pandemic that has wrought an unprecedented drop in global demand for natural gas, it seems like the moment to examine the turbulent present and possible future of the cleanest fossil fuel.
On June 25th, 2010 – almost exactly a decade prior to Chesapeake’s fall – MIT’s Energy Initiative (MITEI) announced the release of a detailed study on the “Future of Natural Gas.” The report voiced full-throated, heavily-footnoted support – from one of the country’s most prestigious research universities – for expanding the role of natural gas in the U.S. energy economy.
“Much has been said about natural gas as a bridge to a low-carbon future, with little underlying analysis to back up this contention,” said Ernest J. Moniz, the longtime MIT physics professor and MITEI director who led the team of researchers behind the report. “The analysis in this study provides the confirmation — natural gas truly is a bridge to a low-carbon future.”
Moniz and his co-authors celebrated natural gas’s game-changing economic potential as a cheap feedstock for power plants and petrochemical plants alike. They shrugged at the environmental consequences of expanded production and use of shale gas as “challenging but manageable.” Shale gas, they argued, would usher in an age of long-sought “energy independence.” More natural gas infrastructure, they asserted, would be, on balance, good for the climate, as it would reduce dependence on more carbon-intensive coal and oil.
The study was received warmly by its intended audience of policymakers, energy analysts and investors. In 2013, President Barack Obama appointed Moniz as his Secretary of Energy. A year later, Obama would proclaim in his State of the Union address that “America is closer to energy independence than we’ve been in decades … One of the reasons why is natural gas – if extracted safely, it’s the bridge fuel that can power our economy with less of the carbon pollution that causes climate change.”
Flash forward to 2020: it all largely came to pass. The vision laid out a decade ago in the MITEI report became a sort of self-fulfilling prophecy. The deluge of cheap domestic shale gas has crippled coal. Chesapeake’s aggressive, debt-driven approach ultimately proved to be its own undoing, but all that drilling also did far more than any particular piece of policy to shrink the U.S. coal industry. In 2010, coal provided nearly 45% of electricity in the U.S, while natural gas’s share was 24%. By 2020, the ratio had flipped: coal’s share was under 22% and gas dominated with 40%.
Today, the U.S. is in the midst of a natural gas infrastructure boom. More than 175 gas-fired power plants are currently on the drawing board or under construction nationwide. Dozens of new pipelines are planned or under construction to bring natural gas from major shale basins to fuel those power plants, to provide feedstock for new petrochemical facilities in Pennsylvania, Ohio and Louisiana, or to undergo super-cooling at six recently built liquefied natural gas (LNG) terminals for export to energy-hungry markets abroad.
And the “bridge fuel” trope is now almost ubiquitous, popping up in the first or second paragraph of nearly every news story about natural gas – almost as often as it does in the promotional materials of the American Petroleum Institute (which recently launched an effort to rebrand its collective members as the “gas and oil” industry). Presidential candidates Amy Klobuchar and Joe Biden were still touting it as a “transitional fuel” in Democratic primary debates, wary of alienating oil and gas industry workers in key swing states like Pennsylvania.
But even as its widely cited conclusions helped cement in place the “bridge fuel” narrative, the MITEI report’s provenance received little scrutiny. Its primary funder was the American Clean Skies Fund, a nonprofit that functioned largely as a pro-natural gas lobbying group. It was founded and largely financed by Aubrey McClendon, the high-living, risk-loving cofounder and long-time CEO of Chesapeake.
As he watched natural gas prices remain stubbornly, disastrously low – much too low to make a profit – McClendon set himself the task of drumming up new sources of demand, and to boost use of gas at the expense of other energy sources, including coal, oil and renewables. His biggest target was Americans’ cars and trucks: he lobbied relentlessly for policies to encourage the use of natural gas as a transportation fuel, to little avail.
As McClendon explained to reporters at the time, he’d prefer that American drivers fill up on compressed natural gas instead of gasoline. “If for some reason this country refuses to use this wonderful fuel…I have to put my gas up for sale to somebody,” he said in 2009.
So, he tried another tack. In 2009, McClendon made a phone call to Charif Souki, the founder of Cheniere Energy. That year, Chesapeake was riding high and Cheniere was a company on the verge of bankruptcy: at one point its stock price fell below $2.00. Souki’s very expensive bet on building a facility in Cameron Parish, Louisiana to import gas from foreign suppliers was being ruined by the domestic glut of gas produced by Chesapeake and other fast-growing fracking outfits.
In his book The Frackers , Gregory Zuckerman reports that McClendon invited Souki to meet with him at his lavish headquarters in Oklahoma City. “Why don’t you build me an export terminal?” he asked.
McClendon suggested that Souki retool his facility, called Sabine Pass, to send gas in the other direction. By building liquefaction “trains” to supercool natural gas to negative 260 degrees Fahrenheit, Souki could load Chesapeake’s gas onto tanker ships that would carry it onward to Japan, India, China and wherever foreign utilities and industries might be eager to buy McClendon’s fuel.
Souki went home, gave the matter some thought, retooled his company, and rounded up investors. In April 2012, the Federal Energy Regulatory Commission (FERC) approved Cheniere’s application to build an export terminal at Sabine Pass – the first to be constructed in the U.S. in over 50 years. It shipped its first cargo in 2016. In January 2020, Sabine Pass loaded its 1000th cargo of LNG.
It may have been a Plan B for McClendon, but it proved prophetic. The pivot both saved Cheniere and birthed a new and unexpected era in U.S. natural gas infrastructure. Today, Cheniere is the dominant LNG exporter, and the single biggest buyer – the Walmart, if you will – of domestic natural gas.
In 2017, the U.S. became a net exporter of natural gas for the first time since 1957, according to the Energy Information Administration (EIA). McClendon didn’t live to see it: he died in March 2016 when his car crashed into a bridge abutment, the day after he was indicted on federal charges of price-fixing.
But America’s LNG export boom might prove to be perhaps Chesapeake’s most durable legacy, like a seed pod cast off by a dying tree.
New LNG export terminals have since sprouted up along the Gulf Coast like giant steel mushrooms. Six LNG terminals currently operate in the U.S.; more than a dozen others are in various stages of planning or construction. This so-called “second wave” of LNG projects, pursued by giants like Royal Dutch Shell and independent startups with names like VentureGlobal and NextDecade, seek to replicate Cheniere’s success. So many entrants have piled in that FERC last year announced it would open a new office in Houston, dedicated solely to supervising the LNG export industry.
The “Forever Fuel”
“We want to make sure that natural gas has a meaningful role not only today, not only in 20 years, but forever,” said Jack Fusco, the current CEO of Cheniere Energy, at an energy conference in early 2019.
The new “bridge” would seem to be a tanker ship. LNG exports are now the biggest source of projected long-term growth in demand for U.S. natural gas in the coming decades.
“Gas suppliers upstream in the U.S. are really counting on LNG, because demand from power sector and buildings in the U.S. is flat or declining,” said Pete Erickson, a senior scientist at Stockholm Environment Institute, an international research group focused on climate and sustainability policy. “Their hope is absolutely for petrochemical (facilities) and LNG exports to fill that gap and even allow for expansion.”
New LNG project developers are pinning their biggest hopes on Asian markets that might prove increasingly interested in swapping dirty coal for cleaner-burning gas. In February, Shell released its Global LNG Outlook, which forecast that global demand for LNG would double by 2040. Demand in Asia, especially – anchored by energy-hungry China in the near-term, and fast-growing India over longer time frames – looked set to grow well into the middle of this century, Shell’s analysts predicted.
But both the financial risks and the climate-related risks of these projects have grown more complicated over the past few years.
Recently, some serious cracks have started to show in the edifice of the “bridge fuel” narrative. Natural gas is the fastest-growing fossil fuel globally. It’s also the fastest-growing source of greenhouse gas emissions, according to a study last year by researchers at the Global Carbon Project.
A raft of recent scientific studies has revealed that the natural gas industry is a much larger source of greenhouse gas emissions than previously thought. New detection devices mounted on airplanes, satellites and ground-based systems have revealed that the entire fossil gas value chain leaks much more methane – a super-potent greenhouse gas, and the primary constituent of natural gas – than either Environmental Protection Agency or industry estimates suggest.
At decade’s end, a 2019 modeling study authored by a MITEI-affiliated researcher, Jessica Trancik of MIT, found that methane leaks would have to be reduced by as much as 90% to justify any further expansion of natural gas infrastructure from a carbon-saving perspective, instead of investing in low-carbon electricity sources like solar and wind.
Nervous about the damage these leaks could do to the prevailing perception of natural gas as a “clean” fuel, many major oil and gas companies have been pledging to cut their methane leak rates.
Last year, when I spoke with Fiji George, Cheniere’s climate and sustainability director, he pointed to International Energy Agency (IEA) projections that natural gas will rise to make up some 25% of the global energy supply by 2050, even in a scenario that includes policies to keep global average temperature rise under two degrees Celsius.
“We want to make sure that Cheniere’s LNG supply is in that 25%,” he said. Today, the lowest cost suppliers rule. But soon, he argued, carbon emissions intensity will be just as important a factor as low-cost production in determining which LNG exporters survive and thrive. That’s why, he emphasized, Cheniere took the problem of methane leaks seriously. “We see climate and providing lowest methane intensity and carbon intensity LNG to our customers as a competitive advantage, allow them to ‘comply’ with their Paris agreement commitments,” he said.
But whether coal-dependent countries like India and Japan – which is still planning to build 22 new coal-fired power plants in the next five years – pivot at a large scale toward lower-carbon natural gas will ultimately come down to price.
In much of the world, the price of LNG is contractually linked to the price of oil, explained Nikos Tsafos, a senior fellow and natural gas expert at the Center for Strategic and International Studies. This has until recently kept prices relatively high, and limited LNG’s encroachment into coal’s market share.
“The biggest breakthrough you could have in terms of gas markets would be to price gas in way that it could beat coal, and make it more attractive for Asian buyers to use more gas than coal,” Tsafos said. “Coal use in Asia is our number one problem climate-wise.”
But not everyone agrees that more LNG is what the world needs to slow its emissions.
“Gas is still a fossil fuel,” said Erickson. “In a world where we need to go to net zero emissions in a matter of decades. Even though it’s the lowest-carbon fossil fuel, gas needs to be phasing out around the world.”
Erickson co-authored the 2019 Production Gap Report sponsored by the UN Environment Programme, which warned that “the continued rapid expansion of gas supplies and systems risks locking in a much higher gas trajectory than is consistent with a 1.5°C or 2°C future.” No matter how you parse it, he said, LNG doesn’t add up as a climate solution.
“There may be good reason to build out more gas in the short term if it knocks out coal,” he said. “That has helped us in the U.S. But the economics of renewables have advanced so rapidly. Renewables are going to be able to compete even with gas in a lot of markets really soon if they are not already.”
He cited a series of recent modeling studies examining the effects on global greenhouse gas emissions of expanding U.S. natural gas supply and exports in the form of LNG.
“In the short-term expanding gas does help knock out coal,” he added, “but once you’re a few years out, instead the effect of new gas is to displace renewables, because of that lock-in effect.”
The Pandemic Pause
If it’s a risky bet for the climate, in the wake of the economic fallout from the Covid-19 pandemic, building more natural gas infrastructure also seems an increasingly risky proposition for investors.
From our current vantage point, the future of natural gas looks far cloudier than it did in June 2010. It was a particularly rough month for LNG exporters. There was still too much gas being produced, cratering demand for it, and nowhere left to put it. Storage tanks in Europe were nearly full. Tanker ships were re-routed, some just circling at sea, serving as floating storage vessels, caught in global commodity limbo.
At least 33 cargoes of LNG slated for export in June were cancelled; another 45 were already cancelled for July. Most were Cheniere’s.
“LNG has nowhere else to go is when you get these cancellations,” said Erin Blanton, a research scholar at the Center on Global Energy Policy at Columbia University.
In mid-March, just a month after issuing its rosy Global LNG Outlook, Shell announced that it would withdraw from a long-proposed LNG export project in Lake Charles, Louisiana. Shell executives insisted the move was about freeing up cash in a tough market, not an indication that they had soured on the long-term prospects of LNG. (Shell became the world’s largest trader of LNG in 2016.)
“The industry is making significant financial bets on gas,” said Andrew Logan, senior director of oil and gas at Ceres, a nonprofit that advocates for sustainable investment. “Shell has been assuming that gas will have a place in a low-carbon future, and I think that’s an open question.”
Some saw the Lake Charles move as an indication that Shell might be rethinking that bet.
“Was Lake Charles a sign that they’re not going to commit between 2025 to 2045 to investing in more LNG assets if they’re aiming to be carbon neutral by 2050?” said Blanton. In April, Shell announced its commitment to achieving “net zero” emissions of greenhouse gases by 2050, and to align its business with the Paris Climate Agreement.
“I don’t know if this is set in stone,” said Blanton, “but I could see them not making the kind of continued investment in LNG that we’ve seen historically, because of the (lower-carbon) trajectory they now say they’re going in.”
After all, even if Shell and other oil and gas producers could wrestle their methane leak rate close to zero, their product is still, at the end of the delivery chain, meant to be burned. That combustion produces carbon dioxide, the primary driver of atmospheric warming. And with $20 to $30 billion price tags, once LNG export terminals are built, powerful financial and political incentives will be in place to keep them operating for many decades to come.
The “second wave” of LNG projects already faced other headwinds, most notably the mounting hostility between the U.S. and Chinese governments –including a trade war, new retaliatory tariffs and angry sparring over the coronavirus response. China is the indispensable buyer for many LNG developers.
“In talking with members, I don’t hear they are closer to signing long-term agreements with Chinese buyers than were six months ago,” Charlie Reidl, executive director of the Center for LNG, the trade association representing LNG export companies, told me.
Then the pandemic struck. The economic lockdowns imposed to prevent the spread of Covid-19 cratered demand for oil in spectacular fashion – prices went negative in April. Demand for natural gas also has fallen significantly, if not as precipitously. The IEA is now warning that global demand for natural gas could fall even lower in coming months, and project that prices could remain low for years to come.
Remarkably, even after Covid-19 emerged in the U.S., triggering lockdowns and economic wreckage, new LNG export terminals and trains were still being approved by regulators. In mid-March, FERC voted to approve the first LNG export terminal on the West Coast, in Coos Bay, Oregon.
“I believe America will continue to be a net exporter and keep its place on the world energy stage,” said chairman Neil Chatterjee. “All the signals I see from domestic participants, as well as our international allies [are] that people continue to be bullish about the prospects for US LNG,” he said.
In fact, the Trump administration has promoted LNG heavily, countering Russia’s use of its vast supplies of natural gas as leverage over the European countries that depend on it for heating and power. Since 2016, FERC has approved several new LNG liquefaction trains. In May 2019, the Department of Energy granted approval for an added liquefaction train at Freeport LNG Terminal in Texas. In announcing it, one senior DOE official referred to LNG as “freedom gas”; another said the move would allow “for molecules of U.S. freedom to be exported to the world.”
Most LNG facilities are built with debt-based financing from major banks, backed by long-term contracts with buyers – frequently utilities in Asia, South America or Europe. Before the pandemic, many projects by independent developers were struggling to line up these long-term deals. With their economies slowed to a crawl, companies in Japan, China, India and South Korea are now even less interested.
And without those contracts in hand, investors are wary. The economic downturn is dampening investors’ enthusiasm for these costly projects. Projections for the amount of LNG capacity that will come online in 2021 have been slashed in half from rosier pre-pandemic forecasts.
With prices around the world “unbelievably low,” Blanton said – in Europe around $1.40 per MMBTU, and in Asia around $2.00 per MMBTU (Million British Thermal Units, the unit of choice for the global gas trade) – “it’s not a market you want to invest in at all.”
“If it costs you six dollars just to make the gas and the price you get is two bucks,” she said, “even if we have a recovery, a $20 billion LNG export project is going to be far down the list of where investors’ appetite is.”
The LNG export capacity that’s currently in place, she said, “is likely what we’ll see for the foreseeable future, but we’re not going to have a second wave.”
The pandemic-driven pause on building new export capacity could lead to demand outpacing supply later this decade, and higher prices. That would mean more profits down the road for Cheniere and other LNG exporters. But it also makes natural gas less competitive with renewables.
Reidl told me that he expects the effects on supply to linger long after the pandemic is over. “Raising money in this environment is difficult,” he acknowledged. “All of this being paused, the only thing that’s doing is costing those commercial developers money.”
Projects that were awaiting final investment decisions might have to go through an entire re-design and re-permitting process, if the delays are long enough.
“That’s a multi-year process,” Reidl said. “Then you’re faced with further delay in the market, with a build time of four or five years. You could theoretically see a scenario of 2028 before you see the next wave of projects operating. All predicated on demand being there.”
Despite all this uncertainty, some energy experts think the pandemic could look like a mere speed bump for the LNG industry.
The winnowing effect of the pandemic could even lead to higher prices – and a stronger position – for low-cost LNG exporters later this decade, if the slowdown “rebalances” supply and demand by wiping higher-cost projects off the drawing board, said Nikos Tsafos.
“Pre-Covid-19, there was a sense that we were seeing too much investment in LNG,” said Tsafos. “It felt kind of like a last hurrah – if you build it now, it takes four years to build, and you’re hoping to get your money back in 20 years. If you don’t build it now, you’ll probably never get your money back. In some ways the Covid crisis corrects that. Not overbuilding now may mean you don’t crash the price.”
“Over long time horizons, the industry can sustain a few years of bad results,” said William-Derry of IEEFA. “But a huge amount depends on China and India, as long-term buyers. A lot of people talk about demand. China will be using a lot more LNG. But what price are they willing to pay?”
In its otherwise gloomy June global gas demand forecast, even the IEA saw glimpses of optimism for LNG. It predicted that the global LNG trade would increase 21% by 2025.
“Emerging Asian markets remain the driving force behind the expansion of LNG imports, led by China and India, while the US accounts for almost all of the net growth on the export side,” it projected.
“Just a dream”
“This whole LNG story is just a dream,” said Kingsmill Bond.
His voice dripped with skepticism over our trans-Atlantic Skype connection. Bond is a chartered financial analyst and certified management accountant, who worked for many years as an equity analyst at major banks from London to Moscow to Hong Kong. Now he’s a senior analyst and strategist at Carbon Tracker, a think tank that studies the risks and opportunities of the energy transition for the fossil fuel industry, the financial markets and the wider global economy.
Bond believes that the fossil fuel industry is confronting imminent peak demand for their products. Before the pandemic struck, Bond argued that peak demand – the moment when consumption of oil, gas and coal begins to permanently decline – would come sometime in the mid-2020s.
Now he’s convinced that 2019 will prove to have been the year that world’s appetite for fossil fuels reached its apex.
After coal and then oil, natural gas will be the last to peak. But precisely when it happens, he said, it’s almost irrelevant.
“I, like everybody else, assume gas demand will carry on rising until it peaks in the 2030s,” he said. “But it’s not volume of demand that matters. It’s the price.”
To Bond, the daily swings in natural gas futures prices and various forecasts about the “belief” in long-term demand is all just noise. The structural decline is a simple math problem, one that can’t be wished away.
“Whenever I talk to gas analysts, we have this long and boring debate,” Bond said. “They say prices will be high because demand is high. I say, well, no actually. I say, ‘Look guys, it’s simple economics.’ About 40% of gas is used for electricity generation. You’re competing directly with renewables, which gets cheaper by five to 10 percent every year. If you want to compete, drop your price the same amount every year. That’s it. It’s that simple.”
Renewables like wind and solar have a small share of the overall energy demand today, but that share is growing at a much faster rate than any fossil fuel. Before long, he predicts, all of the growth in demand will be going to renewables. And on top of it all, global fossil fuel demand is plummeting because of the pandemic.
“If fossil fuel demand falls eight percent in 2020, and the natural growth rate of fossil fuels is one percent per year, by 2025, these new energy technologies will be 5 or 6 percent of the system,” he says. “And Covid brings the moment of the peak forward.”
This acceleration, he argues, is why India and China won’t save the U.S. natural gas industry, why the tanker ship will fare no better than the “bridge,” and why investors should think twice before loaning LNG developers $20 or $30 billion to build what could soon be a stranded asset too unprofitable to operate.
“If you’re an LNG exporter, the risks will be higher than you think,” he said. He cited a recent winning bid in India to provide “round-the-clock” renewable electricity to a utility at an average price of $48 per megawatt-hour – cheaper than what many utilities in India pay for coal-fired power now – as an ill omen for the long-term prospects of LNG.
“LNG is expensive stuff,” he noted. “It costs a lot to cool it down, transport it in the boat, and turn it back into gas.” It could be much cheaper to blanket India with solar panels, much sooner than expected, than to build the country’s infrastructure required to offload, re-gasify, transport and burn natural gas. “People look at India and China and say, ‘Wow, India will go from 5% to 40%!’” he said, referring to natural gas’ share of total energy consumption. “Why would it, when it’s so expensive?”
“A lot of these (investors) realize the game will be up at some stage,” he added. “Now this has brought it forward by five years.” The pandemic’s fallout, he contends, has wiped out some of the best years that a project developer or investor has to recoup their costs. “People are much more aware of the fragility of some of the decisions they’re making. You can see it in the value of US shale stocks. Investors are saying enough is enough.”
I asked the former investment professional, the one who managed the energy fund of a large asset management firm for years, what he made of Kingsmill Bond’s analysis.
He, too, had assumed that the demand for a lower-carbon fossil fuel would grow for decades. Before he left the industry a few years ago, he conceded, “for the last ten years I never worried about natural gas consumption because I saw how much coal India and China was consuming.” But he found Bond’s case persuasive.
“What Bond is saying is that at some point the future looks too uncertain or too bleak that it brings it all forward,” the former fund manager said. “In the sense that people in the investment community doesn’t believe in the future, then it doesn’t believe in the present. It’s not going to give you money today if its worried about getting it back down the road. When that happens that will affect the supply for natural gas.”
The effects of investors’ dawning realization that this period of structural decline – life on the other side of the ‘peak’ – might be approaching would be to alter the bets they place today. And in doing that, they will alter the trajectory of what gets built, and how much carbon pollution gets locked in for decades to come.
There are two cost trends that are cause for concern for natural gas companies, from the upstream (drilling) to the midstream (pipelines) to downstream (power plants). One is the cost of capital. The interest they have to pay on debt from big banks and other lenders – the returns demanded by increasingly skeptical investors – is rising.
The other is the cost of renewable energy. It is heading relentlessly downward, faster than anyone has expected. In April, research by Bloomberg New Energy Finance showed that solar and onshore wind were now the cheapest new electricity generation sources for two thirds of the global population.
These two trends are accelerating. The cost of borrowing money has flipped: whereas oil and gas used to have favorable lending rates, renewable energy project developers are now paying interest rates as low as 3%; oil and gas producers are paying as much as 20% for long-term loans to finance their ventures. Goldman Sachs recently released a research note for investors projecting that “renewable power will become the largest area of spending in the energy industry in 2021, on our estimates, surpassing upstream oil & gas for the first time in history.”
These trends also help explain why, before the pandemic emerged, journalist and prominent climate activist Bill McKibben was feeling more optimism than he has in a long time about the prospects for structural change. He’s been spending more time pressuring the financial community, as part of a new campaign calling on banks to stop financing new fossil fuel projects.
“Natural gas was always their fallback,” McKibben said. “Now they say, ‘We kind of understand these guys are not the future.’ Now it feels like we’re pushing on an open door.”
“One good thing about working with the financial community is that they are heavily reality-based. They all read the reports. The only thing they care about is money. And when you show them that there’s a much cheaper thing coming, they understand where it’s going to come from.”
Big investment firms like to hedge their bets. But there are signs of a structural shift taking place in the way they assess risk. Blackstone, the biggest private equity firm in the world, has been an enthusiastic backer of natural gas pipelines, drillers and LNG developers over the past several years. David Foley, head of Blackstone’s energy group, has compared the firm’s natural gas investments to supplying picks and shovels to miners during the Gold Rush. (“We don’t really care about the gold price, we just need it to be sufficient that people continue to mine.”)
Blackstone was also the investor that Charif Souki turned to after his conversation with Aubrey McClendon back in 2012. The firm plowed nearly $2 billion into the project. Last September, Blackstone announced it was considering selling its 42% stake in Cheniere, because it’s been so successful. “We’re very happy with the investment,” Foley said. “If someone else sees that value and wants to make an offer, we’d have to consider it. We hold things for a long time, not forever.”
But Blackstone doesn’t see any of the second wave LNG projects as attractive investments. That includes Tellurian, an LNG venture founded as a kind of second act in 2016 by Charif Souki, after he was pushed out of Cheniere by activist investor Carl Icahn, who took issue with his strategy to double the company’s export capacity amidst a supply glut.
Since the pandemic struck, Tellurian has laid off 40% of its staff. It has struggled to find financial backers to cover the $28 billion price-tag of its proposed Driftwood LNG project at Calcasieu Parish in Louisiana. Souki is now selling his $220 million Aspen ranch.
Meanwhile, in January Blackstone made a $850 million investment in a solar power company. In March, Blackstone’s energy-focused fund acquired a Canadian company that’s pioneered large-scale battery storage systems.
“The question is how long the past can hang on,” said McKibben. “How long can the natural gas industry retain the support and backing of the financial community? It’s disintegrating faster than anyone could have predicted.”
“What Bond is suggesting,” the former fund manager added, “is there will be enough of renewables eating away at demand that the price will be low enough such that the supply demand will peak otherwise than you may think. And if the investment community sees that coming before that happens, it will stop giving the natural gas industry money, and the supply will peak earlier than it would have. Without capital, these commodities all peak fast.”
Jonathan Mingle, a freelance writer in Vermont, is examining the future of natural gas during his APF fellowship.
© 2020 Jonathan Mingle
